Well bore wall clean up method

ABSTRACT

A well cleanup process involves removing an impermeable filter cake from a formation face with thermochemical and chelating agents to allow formation fluids to flow from a reservoir to a wellbore. The method may be used with oil and water-based drilling fluids with varied weighting agents, e.g., bentonite, calcium carbonate, or barite. Such thermochemical agents may involve two salts, e.g., NO2− and NH4+, which, when mixed together, can generate pressure and heat, in addition to hot H2O and/or N2. For example, the thermochemical agents may comprise Na+, K+, Li+, Cs+, Mg2+, Ca2+, and/or Ba2+ with NO2− and NH4+ with F−, Cl−, Br−, I−, CO32−, NO3−, ClO4−, and/or −OH. The thermochemical agents in combination with a chelator such as EDTA can removed the filter cake after 6 hours with a removal efficiency of 89 wt % for the barite filter cake in water based drilling fluid, exploiting the generation of a pressure pulse and heat which may disturb the filter cake and/or enhance barite dissolution and polymer degradation.

STATEMENT REGARDING PRIOR DISCLOSURES BY INVENTOR(S)

Aspects of the present disclosure are described by the inventors in“Well Cleanup Using a Combined Thermochemical/Chelating Agent Fluids,”which published online in J. Energy Res. Techn. 2019, 141, 102905 on May8, 2019, which is incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION Field of the Invention

The present disclosure relates to formulations and methods for freeingoil well filter cakes from residues, particularly drilling fluidresidues, particularly implementing thermochemical reactions to produceheat and/or pressure, preferably in combination with a solubilizingagent, such as a chelator, particularly for barite-containing fluids.

Description of the Related Art

The well cleanup process is the first stage in well completionoperations. In well cleanup, the oil and/or gas (or water) well iscleaned of drilling fluid residue. The drilling fluid residue is formedduring overbalanced drilling operations due to the difference betweenthe hydrostatic drilling fluid pressure and the reservoir pressure. Thispressure difference generally forms a drilling fluid residue on theformation face.

The drilling fluid residue is a thin, impermeable layer that can preventthe flow of oil and gas from the reservoir to the wellbore. The drillingfluid residue, i.e., impermeable thin layer or filter cake, should beremoved during the well cleanup operations in order to allow thereservoir fluids to flow from the reservoir to the wellbore and then tothe surface.

The drilling fluid, or components thereof, can also cause damage to thereservoir due to the invasion of its base fluid (water or oil) andweighting materials, polymers, etc. These components of the drillingfluid, such as weighting materials, base fluid, polymers, etc., willgenerally flow through the reservoir until the filter cake is formed.The flow of these components to the reservoir can form a layer ofreduced permeability, called a skin, around the wellbore. In addition toskin damage, other damaging mechanisms can be introduced during thedrilling process, such as wettability alteration in the near-wellborezone, formation of emulsion, and clay swelling.

Well cleanup problems can be more difficult or severe in horizontalwells compared to vertical wells, which can be attributed to longercontact times between the drilling fluid and the reservoir sectionduring horizontal drilling. Several studies have indicated thatreservoir productivity can be affected, e.g., diminished, due todrilling fluid residue damage.

While drilling vertical and horizontal wells, the drilling fluid canform a rigid filter cake on the formation face. The drilling fluid istypically contaminated with fine particles from the drilled-rocks. Thesefine particles promote filter cake formation and generally become majorconstituents of the filter cake.

Several studies have shown that the filter cake formed on the formationface is different from that formed in the laboratory. The effect of thedrilled-rock fine particles is not always considered or adequatelyaccounted for in the laboratory. Drilling fluid samples used in thelaboratory to assess the formation damage risks of these fluids do notrepresent the actual situation in the field. Field samples of drillingfluids should preferably be used in the laboratory to assess theformation damage potential.

Drilling fluid cleaning equipment at the surface of a well usuallycannot remove the contaminants encountered during the drilling process.Some of these contaminants may have the same size as the drilling fluidweighting materials, such as sand and calcite particles from the drilledformation. Drilling fluid samples collected from the field as well assimulations of actual drilling processes for a specific well have shownthat the drilled formation solid content can reach 30% in the drillingfluid during drilling a horizontal lateral of 3000 ft. Such a situationwill be more severe in longer laterals.

J. Energy Resour. Technol. 2016, 139(2), 022912 by Ezeakacha et al.(Ezeakacha) describes the effect of particle size in drilling fluidweighting materials on the filtration loss and filter cake in differentsandstone rock outcrops. Ezeakacha does not consider the effect of rockmineralogy on the filter cake formation, neglecting the presence of thedrilled-cuttings effect on the drilling fluid and filter cake formationas well. Ezeakacha reports that the integrity of the filter cake iscontrolled by the particle size distribution of the weighting materialsas well as the tested rock permeability.

Different additives can be included in the drilling fluid formulation toreduce infiltration to the reservoir section and minimize the risk ofdamage to the formation. J. Energy Resour. Technol. 2018, 140(5), 052903by Adewole et al. (Adewole) describes using date pits to improvedrilling fluid rheological properties and reduce filtrate loss to theformation. Adewole reports that a concentration range of 15 to 20 wt. %of date pits can give useful filter cake thicknesses and improve thefluid rheology.

Hydrochloric acid (HCl) has been extensively used in the art to cleanthe wellbore and remove filter cake damage. Horizontal well cleanupusing HCl is a challenging process because of the uncontrolled reactionand inefficiency in the acid placement process in long horizontal wells.

Water based-filter cakes can include polymer materials. Differenttechniques have been developed to remove the polymer materials.Oxidizers and enzymes have been used, but their efficiency typicallydegrades when mixed with acids, and most polymer breakers are not stableat high temperatures. Esters, encapsulated acids, organic acids, or acidprecursors have been used to remove the filter cake formed bywater-based drilling fluids. These acids undergo controlled reaction andcan be used in long horizontal wells to clean the well after drillingoperations, but limitations associated with such acids, includingtemperature stability and dissolution capacity of calcite based filtercakes, remain.

HCl acid has also been investigated in a jetting mode rather thansoaking mode. Mechanical jetting and chemical jetting, using HCl, havebeen attempted as a means to remove calcium carbonate filter cake. Acidjetting has been reported to perform better than acid dissolutionbecause acid jetting can be used to clean long laterals and acid dose,rate, and velocity can be controlled. The contribution of mechanicaljetting of the acid has been reported to perform better than aciddissolution in restoring the well productivity.

The previously mentioned acids were introduced for managing filter cakeswith water containing calcium carbonate. These formulations have notbeen successful when barite (also “baryte”), i.e., a white or colorlessmineral having barium as a main source (BaSO₄), the barite groupincluding barite, celestine (strontium sulfate), anglesite (leadsulfate), and anhydrite (calcium sulfate) with barite and celestineforming a solid, (Ba,Sr)SO₄, is used as a weighting material. Barite isinsoluble in a variety of acids, and extensive research has beenperformed to solve the problem of barite removal in water base drillingfluids.

Chelating agents, such as ethylenediaminetetraacetic acid (EDTA) anddiethylenetriaminepentaacetic acid (DTPA), have been used to removebarite filter cakes. Converters, such as potassium carbonate, have beenadded to such chelating agents to maximize the removal efficiency.Removal efficiencies of up to 95% have been reported using one or moreconverters along with one or more chelating agents, compared to 65%without the use of converter. The barite conversion process usingchelating agents and converters has been found to be effective forremoving water-based barite filter cakes. The barite conversion processhas been found to be non-corrosive to well tubulars under high pressure,high temperature (HPHT) conditions.

In long horizontal and maximum reservoir contact wells, efforts havebeen made to address the issues of uncontrolled and unwanted reactionsby so-called “self-destructive” methods. In a self-destructive method,the drilling fluid includes an encapsulated formulation that decomposesafter the formation of the filter cake. The decomposition of the removalformulation can be homogenous along the horizontal lateral and can cleanthe entire length of the well. A problem of self-destructive methods isthat achieving the correct design of the capsules and the time at whichthe capsules should decompose, which often cannot be controlled.

Reservoir intervals, in addition to sensitive formations, are usuallydrilled with oil base drilling fluids to avoid formation damage. Theseverity of formation damage is a function of the drilling fluidformulation, the reservoir rock(s), and fluid properties. In oil-basedmud, the process of filter cake removal and well cleanup can besubstantially different than that for water-based mud, because of oilresidues in oil-based filter cakes. Oil films must be removed first,then the particles forming the filter cake should be water-wetted beforethe oil film removal, to allow for direct contact between the removalfluid and the solid particles. Water-wetting surfactants and solvents,such as mutual solvents like ethylene glycol monobutyl ether, have beenused to water-wet filter cakes and remove oil films that cover the solidparticles. Delayed breakers or removers, such as organic acids, havebeen used to remove the oil base mud filter cake from differentreservoirs. Micro-emulsions have likewise been used to clean oil and gaswells drilled with oil-based drilling fluids.

High clay content sandstone reservoirs are particularly sensitive towater-based drilling fluids. Therefore, oil-based fluids are typicallyused to drill high clay content sandstone formations. Well cleanup inthese types of formations is typically conducted using single stagemicroemulsion treatment in horizontal wells. Customary durations forsuch treatments are 24 hours, reaching removal efficiencies up to 97%.Microemulsions have been found efficient for cleaning wells drilled withsynthetic oil-based fluids as well. Other additives, such asco-surfactants and surfactants, have been added to such micro-emulsionsto remove both oil and water from the filter cake and from thenear-wellbore area. An important parameter influencing the success ofmicro-emulsion treatments is the average droplet size of themicro-emulsion.

Most known methods for well cleanup with oil-based or water-baseddrilling fluids have issues either in handling, design, or injection.For example, mineral acids such as HCl risk corrosion, organic acidshave incompatibility, solubility, and/or stability issues,micro-emulsions require careful design to clean wells efficiently, etc.Recent methods, such as employing chelating agents with catalysts,require several stages to clean wells due to incompatibilities offormulation ingredients.

CN 101671553 B to Zhu et al. (Zhu) discloses a gas producing solid-foamliquor drainage ball for a watered gas well, mainly consisting of ball Aand ball B. Ball A contains, by weight: 100 to 150 parts of NaNO₂ and 10to 30 parts of foaming agent, such as sodium dodecyl sulfonate orbetaine. Ball B contains, by weight: 100 to 120 parts of NH₄Cl, 5 to 10parts of foam stabilizer, such as hydroxypropyl guar gum, xanthan gum,or hydroxyethyl cellulose; 25 to 40 parts of catalyst, such as citricacid, salicylic acid, or tartaric acid; and 5 to 10 parts of ethylenediamine tetraacetic acid (EDTA). Zhu discloses a self-generation reagentchemical reaction equation of NaNO₂+NH₄Cl→N₂↑+NaCl+H₂O. Zhu's materialsare non-toxic and can produce non-toxic gas after reaction, allowingspecial high-pressure injection equipment to be avoided in oil fieldoperations. Zhu's reagents react chemically in aqueous solution togenerate nitrogen gas and a large number of bubbles, which reduces theliquid column density of the bottom hole effusion, thereby reducing thebottom hole pressure and helping the gas well to reduce the bottom holeeffusion. Zhu does not disclose removing filter cakes from the wall of awellbore in a subterranean formation.

WO 2013/160334 A1 by Nasr-El-Din et al. (Nasr-El-Din) discloses aone-step process comprising introducing into a subterranean formationcontaining a filter cake a composition containing between 1 and 40 wt %of a chelating agent, such as glutamic acid N,N-diacetic acid (GLDA),aspartic acid N,N-diacetic acid (ASDA), methylglycine N,N-diacetic acid(MGDA), and N-hydroxyethyl ethylenediamine-N,N′,N′-triacetic acid(HEDTA), or salts of these, and having a pH of below 7,wherein in onestep the filter cake is at least partly removed and the subterraneanformation is treated. While Nasr-El-Din discloses EDTA as an optionalchelating agent, Nasr-El-Din's method requires a pH of no more than 7,and Nasr-El-Din does not disclose thermochemical agents, let aloneparticular relative amounts of these to a particular chelating agent.

US 2013/0210684 A1 by Ballard (Ballard) discloses a method of removing awater-based filter cake from a wellbore, involving: contacting thefilter cake with a mixture of a non-aqueous, polar solvent, preferablyhaving a dielectric constant >15, e.g., monoethylene glycol (orpropylene glycol or glycerine), and an agent to breakdown the filtercake, preferably an EDTA salt, in <5 wt. % water. Ballard relies on thelow water content of the mixture to slow the degradation of the filtercake. Ballard reports the slow degradation to be surprisingly moreeffective by allowing more uniform removal of the filter cake and a moreefficient use of the mixture, without the tendency to create local holesin the filter cake where the mixture could escape. Ballard's mixturetypically contains >50 wt. % of the polar solvent and Ballard does notdescribes neither thermochemical agents.

US 2011/0005773 A1 by Dusterhoft et al. (Dusterhoft) discloses a methodof treating a subterranean formation on a well bore at least partiallyhaving a filter cake by contacting at least a portion of the filter cakewith a filter cake degradation fluid of a relative permeability modifierand allowing the relative permeability modifier to retain at least aportion of the filter cake degradation fluid in the well bore for a timesufficient to contact the filtercake and allowing the filter cake todegrade. Dusterhoft's relative permeability modifier is only limited tothe capability to reduce the permeability of a subterranean formation toaqueous-based fluids without substantially changing its permeability tohydrocarbons, and in some embodiments may be a hydrophobically modifiedpolymer. Although Dusterhoft discloses a list of optional acidicadditives and a separate list of chelating agents, each including EDTA,Dusterhoft discloses neither thermochemical reagents, nor selecting anyparticular small molecule chelating agent, much less particularlyrelative molar ratios thereof.

U.S. Pat. No. 10,047,278 and US 2019/0016945 A1 by Mahmoud et al.(Mahmoud) discloses a fracturing fluid composition including a chelatingagent, e.g., GLDA, and a polymeric additive comprising a copolymer ofacrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted inan aqueous base fluid, e.g., seawater, and a method of fracking ageological formation using the fracturing fluid composition. Mahmoudfurther discloses using the chelating agent glutamic diacetic acid, andoptionally further agents (up to 15 wt. %) but does not particularlyindicate selecting anything beyond glutamic diacetic acid. Mahmoudindicates that various ions may be present in the salt water, includingnitrites, chlorides, ammonium, and sodium ions, but Mahmoud does notdisclose targeted thermochemical agents.

US 2019/0100687 A1 by Socci et al. (Socci) discloses compositions andmethods for degrading filter cakes and filter cake removal, from asubterranean borehole. Socci's composition has an unencapsulatedperoxygen and a surfactant, which is allowed to remain in contact withthe filter cake at a temperature above 165° F. (73.9° C.) for a periodof time sufficient to degrade the filter cake, resulting in acidicconditions and eliminating any need for follow up acid treatments.Socci's peroxygens are sodium persulfate, potassium persulfate, andammonium persulfate. Socci mentions optionally using a chelating agent,such as EDTA, but does not describe thermochemical agents, aside frommentioning ammonium chloride in brine.

Sci. Techn. Rev. 2012, 30(34), 36-40 by Yin et al. (Yin) disclosesaddressing heavy oil fluidity and viscosity problems with a chemicalthermal and catalysis system including NaNO₂—NH₄Cl at 4 mol/L. Yinreports that NaNO₂—NH₄Cl can raise the sample temperature by 150° C.from an initial reaction temperature of 60° C., but Yin requires a fattyacid-nickel catalyst as a heavy oil viscosity reducer. Yin does notdisclose a method of removing a filter cake from the wall of a wellborein a subterranean formation.

In light of the above, a need remains for filter cake removalformulations and methods, particularly for subterranean and horizontalwellbores, and particularly using borites, while preferably avoiding thecomplex formulas and equipment of the art, such as employingthermochemical reagents alongside chelators in particular molarrelationships, e.g., to generate pressure and heat in situ, and methodsof making and using such formulations.

SUMMARY OF THE INVENTION

Aspects of the invention provide wellbore filter cake removalcompositions which may comprise, in an aqueous solution at a pH of atleast 10: 1 to 75 g of an ammonium salt per 100 mL composition; 1 to 75g of nitrite salt per 100 mL composition; and at least 20 gethylenediamine tetraacetic acid per 100 mL composition. Such inventiveformulations may be modified by any permutation of the featuresdescribed herein, particularly the following.

The nitrite salt and the ammonium salt may be in a molar ratio in arange of from 1.175 to 1 to 1 to 1.175. The ammonium salt may be anammonium halide and/or the nitrite salt may be an alkali metal salt. Theethylenediamine tetraacetic acid may comprise a potassium counterion permolecule.

Aspects of the invention provide methods of removal of filter cake massfrom a wellbore wall in a subterranean formation using any permutationof the inventive composition(s) described herein. Such methods maycomprise: introducing into a wellbore an aqueous composition onto awellbore face coated with the filter cake mass; allowing the aqueouscomposition to reach a temperature in the wellbore sufficient toinitiate an exothermic chemical reaction of the components of theaqueous composition and thereby cause a temperature and/or pressuresurge at the wellbore face to disrupt the filter cake from the well boreface. The aqueous composition may comprise, at a pH of no less than 10:a first combination comprising a hydrated sulfate salt and guar or apolyacrylamide or a second combination comprising a nitrite salt and anammonium salt; and at least 20 wt. % ethylenediamine tetraacetic acid,based on total aqueous composition weight. Such methods may be modifiedby any permutation of the features described herein

In the second combination the ammonium salt and the nitrite salt mayeach be at a concentration in a range of from 0.5 to 15 M, particularly1 to 5 M. The ammonium salt may be an ammonium halide. The nitrite saltmay be an alkaline metal or alkaline earth metal nitrite. The nitritesalt may comprise Na⁺, K⁺, Li⁺, Cs⁺, Mg²⁺, Ca²⁺, and/or Ba²⁺ with thenitrite salt. The ammonium salt may comprise F⁻, Cl⁻, Br⁻, I⁻, CO₃ ²⁻,NO₃ ⁻, ClO₄ ⁻, HSO₄ ⁻, SO₄ ²⁻, H₂PO₄ ⁻, HPO₄ ²⁻, PO₄ ³⁻, and/or ⁻OH withthe ammonium salt. At least 95 wt. % of the nitrite salt may be sodiumnitrite, relative to the total nitrite salt weight. At least 95 wt. % ofthe ammonium salt may be ammonium chloride, relative to the totalammonium salt weight. A molar ratio of the ammonium salt to the nitritesalt may be in a range of from 1.175 to 1 to 1.175 to 1.

The first combination may be used and may comprise: the polyacrylamide;and an alkaline metal or alkaline earth metal sulfate with saturatedhydration. The hydrated sulfate salt may comprise Na⁺ and/or Mg²⁺. Thehydrated sulfate salt may comprise at least 95 wt. % Na₂SO₄.10H₂O,relative to total sulfate salt weight. The hydrated sulfate salt maycomprise at least 95 wt. % MgSO₄.7H₂O, relative to total sulfate saltweight.

The ethylenediamine tetraacetic acid may be in a range of from 22.5 to30 wt. % of the total aqueous composition weight. Each ethylenediaminetetraacetic acid molecule may comprise a potassium counterion.

The temperature in the wellbore may be in a range of from 50 to 150° C.,prior to the introducing.

The wellbore may comprise a drilling fluid comprising at least 65 wt. %,relative to all drilling fluid solids, of barite. Inventive methods mayachieve the removal of at least 85 wt. % of the filter cake mass within6 hours. Inventive methods may be ones in which at least 95% of theremoval of the filter cake mass achievable by the method is within 6hours.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the invention and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 shows a representation of the exemplary high pressure, hightemperature (HPHT) filtration set-up used in testing as describedherein;

FIG. 2 shows a plot of the time to reach the maximum reactiontemperature as a function of reservoir temperature using two exemplaryinjection formulations;

FIG. 3A shows an oil-based barite filter cake before removal by anexemplary combined thermochemical-EDTA solution;

FIG. 3B shows oil-based barite filter cake after removal by an exemplarycombined thermochemical-EDTA solution;

FIG. 4A shows a water-based barite filter cake before removal bycombined thermochemical/EDTA solution;

FIG. 4B shows a water-based barite filter cake after removal by combinedthermochemical/EDTA solution;

FIG. 5 shows a chart presenting barite solubility as a function oftemperature in 25 wt. % EDTA at pH 14;

FIG. 6 shows a chart of the effect of temperature on the 25 wt. % EDTAdiffusion coefficient;

FIG. 7 shows a plot of the effect of average barite particle size onbarite solubility in 25 wt. % EDTA at pH 14 at 210° C. for 6 hours; and

FIG. 8 shows a chart of the effect of soaking time on the barite filtercake removal efficiency (water based drilling fluid) in an exemplaryformulation combining thermochemical agents and 25 wt. % EDTA solutionat pH 14.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Aspects of the invention provide wellbore filter cake removalcompositions which may comprise, in an aqueous solution at a pH of atleast 10, 10.5, 11, 11.5, 12, 12.5, 13, 13.5, or 14; 1 to 75 g of anammonium salt per 100 mL composition; 1 to 75 g of nitrite salt per 100mL composition; and at least 20 g ethylenediamine tetraacetic acid per100 mL composition. The mass of ammonium and/or nitrite salt mayindependently be, e.g., at least 1, 2, 2.5, 3, 4, 5, 7.5, 10, 12.5, 15,17.5, 20, 22.5, 25, 27.5, 30, 33, 35, 37.5, 40, 42.5, or 45 g and/or upto 75, 70, 65, 60, 55, 50, 45, 40, 35, 30, 27.5, 25, 22.5, 20, 17.5, or15 g, per 100 mL of composition. The mass of ethylenediamine tetraaceticacid per 100 mL of composition may be, for example, at least 20, 21, 22,22.5, 23, 24, 25, 26, 27, 27.5, 28, 29, 30, or 32 g and/or up to 35, 34,33, 32.5, 32, 31, 30, 29, 28, 27.5, 27, 26, 25, 24, 23, 22.5, 22, 21, or20 g. The nitrite salt and the ammonium salt may be in a molar ratio ina range of from 1.175 to 1 to 1 to 1.175, e.g., at least 1.175:1,1.15:1, 1.125:1, 1.1:1, 1.075:1, 1.05:1, 1.025:1, 1:1, 0.975:1, 0.95:1,0.925:1, or 0.9:1 and/or up to 1:1.175, 1:1.17, 1:1.165, 1:1.16,1:1.155, 1:1.15, 1:1.125, 1:1.1, 1:1.075, 1:1.05, 1:1.025, 1:1, or1:0.975. The ammonium salt may be an ammonium halide, e.g., fluoride,chloride, bromide, and/or iodide, and/or the nitrite salt may be analkali metal salt, e.g., lithium, sodium, potassium, cesium, magnesium,calcium, strontium, and/or barium. The ethylenediamine tetraacetic acidmay comprise a potassium counterion per molecule, e.g., at least 1, 1.1,1.2, 1.25, 1.5, 1.75, 2, 2.25, 2.5, 2.75, 3, 3.25, 3.5, 3.75, or 4potassium counterions per molecule.

Aspects of the invention provide methods of removal of filter cake massfrom a wellbore wall in a subterranean formation using any permutationof the inventive composition(s) described herein. Such methods maycomprise: introducing into a wellbore an aqueous composition onto awellbore face coated with the filter cake mass; allowing the aqueouscomposition to reach a temperature in the wellbore sufficient toinitiate an exothermic chemical reaction, e.g., at least 50, 55, 60, 65,70, 75, 80, 85, 90, 95, or 100° C. and/or up to 150, 145, 140, 135, 130,125, 120, 115, 110, 105, 100, 95, 90, or 85° C., of the components ofthe aqueous composition and thereby cause a temperature (e.g., at least10, 25, 35, 50, 65, 75, 80, 85, 90, 95, 100, 105, 110, 125, or 150° C.up to 200, 175, 150, 125, 110, 100, 90, 80, or 75° C.) and/or pressure(e.g., at least 10, 25, 50, 75, 100, 125, 150, 200, 250, 350, 500, 650,750, or 1000 psi and/or up to 10000, 7500, 5000, 3500, 2500, 2000, 1500,1000, 900, 750, 650, 500, 450, 400, 350, 300, or 250 psi) surge at thewellbore face to disrupt the filter cake from the well bore face. Theaqueous composition may comprise, at a pH of no less than 10, 10.33,10.67, 11, 11.33, 11.67, 12, 12.33, 12.67, 13, 13.33, 13.67, or 14 (orany pH described herein): a first combination comprising a hydratedsulfate salt (e.g., mono, di, tri, tetra, penta, hexa, hepta, octa,nona, deca, undeca, dodecahydrate, or more) and guar or a polyacrylamideor a second combination comprising a nitrite salt and an ammonium salt;and at least 20, 20.5, 21, 21.5, 22, 22.5, 23, 23.5, 24, 24.5, 25, 25.5,26, 26.5, 27, 27.5, 28, 28.5, 29, 29.5, or 30 wt. % (or any range orpercent described herein) ethylenediamine tetraacetic acid, based ontotal aqueous composition weight.

In the second combination the ammonium salt and the nitrite salt mayeach be at a concentration in a range of from 0.5 to 15 M, particularly1 to 5 M, e.g., at least 0.5, 0.75, 1, 1.25, 1.5, 1.75, 2, 2.25, 2.5,2.75, 3, 3.5, 4, 4.5, or 5 M and/or up to 15, 12.5, 12, 11, 10, 9, 8,7.5, 7, 6.5, 6, 5.5, 5, 4.75, 4.5, 4.25, 4, 3.75, or 3.5 M. The ammoniumsalt may be an ammonium halide, or otherwise comprise a non-reactiveanion. The nitrite salt may be an alkaline metal or alkaline earth metalnitrite. The nitrite salt may comprise Na⁺, K⁺, Li⁺, Cs⁺, Mg²⁺, Ca²⁺,and/or Ba²⁺ in the nitrite salt. The ammonium salt may comprise F⁻, Cl⁻,Br⁻, I⁻, CO₃ ²⁻, NO₃ ⁻, ClO₄ ⁻, HSO₄ ⁻, SO₄ ²⁻, H₂PO₄ ⁻, HPO₄ ²⁻, PO₄³⁻, and/or ⁻OH in the ammonium salt. At least 95 wt. % of the nitritesalt may be sodium nitrite, relative to the total nitrite salt weight.At least 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % of theammonium salt may be ammonium chloride, relative to the total ammoniumsalt weight. A molar ratio of the ammonium salt to the nitrite salt maybe in a range of from 1.175 to 1 to 1.175 to 1.

The first combination may be preferably used in some applications andmay comprise: the polyacrylamide (e.g., with Mn of at least 10, 15, 20,25, 30, 35, 40, 45, or 50 kDa and/or up to 100, 85, 75, 65, 55, 50, 45,40, 35, 30, 25, or 20 kDa); and an alkaline metal or alkaline earthmetal sulfate with saturated or at least 50, 60, 70, 75, 80, 85, or 90%saturated hydration sphere (e.g., mono, di, tri, tetra, penta, hexa,hepta, octa, nona, deca, undeca, dodecahydrate, or more). The hydratedsulfate salt may comprise Na⁺ and/or Mg²⁺ as the cation. The hydratedsulfate salt may be a combination of 2, 3, 4, 5, or 6 different hydratedsulfate salts. The hydrated sulfate salt may comprise at least 95, 96,97, 97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % Na₂SO₄.10H₂O, relative tototal sulfate salt weight. The hydrated sulfate salt may comprise atleast 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % MgSO₄.7H₂O,relative to total sulfate salt weight.

The ethylenediamine tetraacetic acid may be in a range of from 22.5 to30 wt. %, e.g., at least 22.5, 22.75, 23, 23.25, 23.5, 23.75, 24, 24.25,24.5, 24.75, 25, 25.25, 25.5, 25.75, 26, 26.25, 26.5, 26.75, 27, 27.25,27.5, 27.75, or 28 wt. % and/or up to 30, 29.75, 29.5, 29.25, 29, 28.75,28.5, 28.25, 28, 27.75, 27.5, 27.25, 27, 26.75, 26.5, 26.25, 26, 25.75,25.5, 25.25, or 25 wt. % (or any percent described herein), of the totalaqueous composition weight. Each ethylenediamine tetraacetic acidmolecule may comprise a potassium counterion, e.g., on average, 1, 1.1,1.15, 1.2, 1.25, 1.33, 1.5, 1.67, 1.75, 1.85, 2, 2.2, 2.4, 2.5, 2.6,2.8, 3, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, or 4 K⁺ counterionsper molecule EDTA (or any average amount described herein).

The temperature in the wellbore may be in a range of from 50 to 150° C.,such as at least 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100° C.and/or up to 150, 145, 140, 135, 130, 125, 120, 115, 110, 105, 100, or95° C. (or any temperature described herein) prior to the introducing,i.e., before the thermochemical agent(s) release heat and/or pressure.

The wellbore may comprise a drilling fluid comprising at least 65, 67,70, 72.5, 75, 77.5, or 80 wt. % and/or up to 95, 92.5, 90, 87.5, 85,82.5, 80, 77.5, or 75 wt %, relative to all drilling fluid solids, ofbarite. Inventive methods may achieve the removal of at least 85, 86,87, 88, 89, 90, 91, or 92 wt. % of the filter cake mass within 6 hours.Inventive methods may be ones in which at least 95, 95.5, 96, 96.5, 97,97.5, 98, 98.5, 99, or 99.5% of the removal of the filter cake massachievable by the method is within 6 hours.

Inventive materials do not require formation into pellets, spheres,cylinders, or the like, and/or require no pressurized treatment beforereaction, e.g., no more than 4.5, 4, 2, 1, 0.75, 0.5, 0.25, 0.15, 0.102MPa.

Inventive formulations may avoid foaming/blowing agent(s) and/or foamstabilizer(s) entirely, or contain no more than 5, 4, 3, 2.5, 2, 1, 0.5,0.1, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to totalformulation weight, of such foaming agent(s) and/or stabilizer(s),individually or in combination, such as hydroxypropyl silicone (HPG),hydroxypropyl tannin, hydroxypropyl guar, xanthan gum (XG), hydroxyethylcellulose (HEC), sodium dodecyl sulfate (AS), and/or betaine (AC),including ethoxylated alcohols, polysaccharides , ethoxylated fattyamines, amine oxides , glucosides, sulfonates, and/or quaternaryammonium salts. Inventive formulations may exclude acidic catalysts, ormay comprise no more than 15, 10, 7.5, 5, 4, 3, 2, 1, 0.5, 0.1, 0.01,0.001, 0.0001, or 0.00001 wt. %, relative to the total formulationweight, of acid catalysts, such as hydrochloric acid, hydroxyaceticacid, lactic acid, hydrofluoric acid, adipic acid, succinic acid,phosphoric acid, glutaric acid, 3-hydroxypropionic acid, carbonic acid,erythorbic acid, citric acid, salicylic acid, glycolic acid, aceticacid, propionic acid, formic acid, methanesulfonic acid, trifluoroaceticacid, trifluoromethanesulfonic acid, and/or tartaric acid. Inventiveformulations may exclude N-acetic acid amino acids, or may comprise nomore than 5, 4, 3, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001, or 0.00001 wt.%, relative to the total formulation weight, of such N-acetic acid aminoacids, e.g., glutamic acid N,N-diacetic acid, aspartic acid N,N-diaceticacid, methylglycine acid N,N-diacetic acid, and/or N-hydroxyethylethylenediamine-N,N′,N′-tri acetic acid, and/or other chelating agents,such as citric acid, nitrilotriacetic acid (NTA), diethylene triaminepentaacetic acid (DTPA) , propylene diamine tetraacetic acid (PDTA),ethylene diamine-N,N′-di(hydroxyphenyl) acetic acid (EDDHA), ethylenediamine-N,N′-di-(hydroxy-methylphenyl) acetic acid (EDDHMA), sodiumethylenediamine-N,N-disuccinic acid (EDDS), ethanol diglycine (EDG),ethylene glycol-bis(β-aminoethyl ether)-N,N,N′,N′-tetraacetic acid(EGTA), 2-hydroxyethyliminodiacetic acid (HEIDA),trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA),ethylenediaminediacetic acid (EDDA), methylglycinediacetic acid (MGDA),glucoheptonic acid, gluconic acid, glutamic diacetic acid, sodiumcitrate, and/or phosphonic acid.

Inventive formulations may exclude mutual solvents, i.e., chemicaladditives soluble in oil, water, acids, and/or other well treatmentfluids, e.g., lower alcohols (methanol, ethanol, 1-propanol, 2-propanol,etc.), glycols (ethylene glycol, propylene glycol, diethylene glycol,dipropylene glycol, polyethylene glycol, polypropylene glycol,polyethylene glycol-polyethylene glycol block copolymers, etc.), glycolethers (2-methoxyethanol, diethylene glycol mono methyl ether, etc.), C2to C2 esters, and C2 to C10 ketones, such as methyl ethyl ketone,methanol, or may contain no more than 5, 4, 3, 2.5, 2, 1, 0.5, 0.1,0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to total formulationweight, of these, individually or in combination. Inventive formulationscan avoid oxidizing agents, such as peroxides, hypochlorites,hypobromites, peracids, persulfates, and/or persulfonic acids, or maycomprise no more than 5, 4, 3, 2.5, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001,or 0.00001 wt. %, relative to total formulation weight, of these,individually or in combination.

Inventive formulations may substantially exclude polymers, particularlypolyionomers, or may comprise no more than 5, 4, 3, 2.5, 2, 1, 0.75,0.5, 0.25, 0.1, 0.05, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative tototal formulation weight, of such polymer(s), such as a hydrophobicallymodified polymer, acrylamido-tert-butyl sulfonate, hydrolyzedpolyacrylamide, etc., individually or in combination.

Inventive formulations may exclude metallic catalysts and/ormetal-containing catalysts, particularly transition metal (containing)catalysts, e.g., Y, Zr, Ti, V, Nb, Ta, Cr, Mo, W, Mn, Re, Fe, Ru, Os,Co, Rh, Ir, Ni, Pd, Pt, Cu, Ag, Au, Zn, Cd, In, Sn, Sb, Pb, and/or Bi,or may comprise no more than 25, 15, 10, 7.5, 5, 4, 3, 2.5, 2, 1, 0.75,0.5, 0.25, 0.1, 0.05, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative tototal formulation weight, of these, individually or in combination.

Relevant ammonium species may include, for example, ammonium acetate(NH₄C₂H₃O₂), ammonium azide (NH₄N₃), ammonium benzoate (NH₄C₇H₅O₂),ammonium bicarbonate (NH₄HCO₃), ammonium bromide (NH₄Br), ammoniumcarbonate ((NH₄)₂CO₃), ammonium chlorate (NH₄ClO₃), ammonium chloride(NH₄Cl), ammonium chromate ((NH₄)₂CrO₄), ammonium dichromate((NH₄)₂Cr₂O₇), ammonium dihydrogen arsenate (NH₄H₂AsO₄), ammoniumdihydrogen phosphate (NH₄H₂PO₄), ammonium fluoride (NH₄F), ammoniumfluorosilicate ((NH₄)₂SiF₆), ammonium formate (NH₄HCO₂), ammoniumhydrogen phosphate ((NH₄)₂HPO₄), ammonium hydrogen sulfate (NH₄HSO₄),ammonium iodate (NH₄IO₃), ammonium iodide (NH₄I), ammonium nitrate(NH₄NO₃), ammonium to oxalate ((NH₄)₂C₂O₄), ammonium perchlorate(NH₄ClO₄), ammonium perrhenate (NH₄ReO₄), ammonium phosphate((NH₄)₃PO₄), ammonium selenate ((NH₄)₂SeO₄), ammonium sulfate((NH₄)₂SO₄), ammonium aluminum sulfate (NH₄Al(SO₄)₂ orNH₄Al(SO₄)₂.12H₂O), ammonium sulfite ((NH₄)₂SO₃), ammonium tartrate((NH₄)₂C₄H₄O₆), ammonium thiocyanate (NH₄SCN), ammonium thiosulfate((NH₄)₂S₂O₃), etc.

Relevant nitrite species may include, for example, barium nitrite(Ba(NO₂)₂), calcium nitrite (Ca(NO₂)₂ or Ca(NO₂)₂.4H₂O), lithium nitrite(LiNO₂), potassium nitrite (KNO₂), sodium nitrite (NaNO₂), ammoniumnitrite (NH₄NO₂), magnesium nitrite (Mg(NO₂)₂), strontium nitrite(Sr(NO₂)₂), zinc nitrite (Zn(NO₂)₂), silver nitrite (AgNO₂), etc.

The thermochemical agents may comprise Na⁺, K⁺, Li⁺, Cs⁺, Mg²⁺, Ca²⁺,and/or Ba²⁺ with NO₂ ⁻ and NH₄ ⁺ with F⁻, Cl⁻, Br⁻, I⁻, CO₃ ²⁻, NO₃ ⁻,N₃ ⁻,ClO₄ ⁻, and/or ⁻OH.

As described herein, a filter cake (also referred to as a cake, mudcake,or wall cake) means the residue deposited on a permeable medium when aslurry, such as a drilling fluid, is forced against the medium under apressure. The filter cake is a layer formed by solid particles indrilling mud against porous zones due to differential pressure betweenhydrostatic pressure and formation pressure. The filtrate is the liquidthat passes through the medium, leaving the cake on the medium. Drillingmuds are usually tested to determine the filtration rate and filter-cakeproperties. Filter cake properties, including cake thickness, toughness,slickness, and permeability, are important because the filter cake thatforms on permeable zones in the wellbore can cause plugging, i.e., stuckpipe, and other drilling problems. Reduced oil and gas production canresult from reservoir damage when a poor filter cake allows deepfiltrate invasion. A degree of filter cake buildup is desirable toisolate formations from drilling fluids, however. In open holecompletions in high-angle or horizontal holes, the formation of anexternal filter cake is preferable to a cake that forms partly insidethe formation, which inside formations have higher potential forformation damage.

For the drilling operation, it may be preferable to have a filter cakethat is impermeable and thin. Practically, the filter cake from API orHTHP fluid loss test should be less than or equal to 1/16 inch. If thedrilling fluid is in poor shape, resulting in a thick filter cake in thewellbore, blocked pipe, stuck pipe and/or high torque/drag may occur.Thick filter cakes increase the contact area between drilling string orany kind of tubular. Drilling into permeable zones that are severelyoverbalanced risk the drill stem getting differentially stuck acrossthese zones. Beyond the drilling string get stuck, the logging tool mayalso become stuck across permeable sands. If the drilling fluid/mud hasa thick filter cake across the wall of the wellbore under dynamicconditions including drilling, working pipe, etc., torque will increase.A thick wall filter cake will also result in high drag while trippingout of the hole.

Aspects of the invention comprise using thermochemical reactions toremove the water-based and/or oil-based drilling fluid filter cake anddesigning the process to improve the removal efficiency in well cleanupin long horizontal wells.

Aspects of the invention include the removal of barite oil- andwater-based filter cakes using a combined solution ofthermochemical/EDTA chelating agent solution in one single stage.Aspects of the invention comprise use of 1:1 molar ratio of athermochemical agent with 25 wt % EDTA chelating agent at pH 14 to yield89% removal efficiency in barite water base filter cake and 83% removalefficiency in barite oil base filter cake in 6 hours. Aspects of theinvention provide generating one or more pressure pulses, e.g., with oneor more thermochemical reactions, optionally combined with temperature,to improve removal efficiency relative to unheated and/or thermochemicalreaction-free conditions. Aspects of the invention include formulationsallowing safe handling and/or minimizing corrosion risk, vialocalization of the reaction, the high pressure, and temperature (only)at the formation face.

EXAMPLES

Materials: Typical field formulations were used for the oil andwater-based drilling fluids to form the filter cake, Tables 1 and 2below list the composition of these fluids, wherein XC Polymer is axanthan gum derivative of molecular weight 1016.8 g/mol, the chemicalformula C₃₆H₅₈O₂₉P₂, the IUPAC name6-[6-[6-(acetyloxymethyl)-2-[3-[3,4-dihydroxy-6-(hydroxymethyl)-5-phosphanyloxyoxan-2-yl]oxy-5-hydroxy-2-(hydroxymethyl)-6-(phosphanylmethyl)oxan-4-yl]oxy-4,5-dihydroxyoxan-3-yl]oxy-2-carboxy-4,5-dihydroxyoxan-3-yl]oxy-7,8-dihydroxy-2-methyl-4,4a,6,7,8,8a-hexahydropyrano[3,2-d][1,3]dioxine-2-carboxylicacid, used as an emulsion stabilizing and gelling agent.

TABLE 1 Drilling fluid formulation of the water-based drilling fluid.Additive Amount Unit Water 0.691 bbl Bentonite 4 lb XC Polymer 0.5 lbKOH 0.5 lb KCl 20.0 lb NaCl 66 lb Barite 352 lb CaCO₃ medium 5.0 lb

TABLE 2 Drilling fluid formulation of oil-based drilling fluid. NameAmount Unit Water 12.28 bbl Oil 24 bbl Calcite 11 lb Barite 42.2 lb KOH0.05 lb Polymer 0.07 lb Viscosifier 5 lb Emulsifier 5.4 lb

Indiana limestone core samples of 2.0-inch diameter and 2.0-inch lengthwere used as filter media to form the filter cake. A high pressure, hightemperature (HPHT) coreflooding set-up was used to form the filter cake,and the same set-up was used to remove the filter cake or the drillingfluid residue. FIG. 1 shows the coreflooding set-up used in theExamples. The polymer is preferably a cellulosic, lignocellulose and/oraminated cellulosic, lignocellulose having quaternary amine groups. Theemulsifier is, for example, Witcomul 3158 that reduces the interfacialtension between oil and water.

Two sets of thermochemical fluids, in addition toethylenediaminetetraacetic acid (EDTA) chelating agent at pH of 14,preferably only the EDTA fluid is at a pH of 14, were used to remove thewater and oil-based barite filter cake. The concentration of EDTA usedin all experiments was 25 wt. % potassium salt of EDTA, i.e., K₄EDTA,because such a potassium salt can have higher dissolving power than thesodium salt. The filter cake for both oil and water-based drillingfluids was formed using the HPHT filtration equipment shown in FIG. 1.The same equipment was used to remove the filter cake.

Methodology: After the generation of the filter cake for two differentdrilling fluids (oil-based and water-based), the HPHT temperature cellwas used to remove the drilling fluid residues (filter cake). The firstset of thermochemical agents was magnesium sulfate, MgSO₄, in additionto a polymer, polyacrylamide or guar (the polyacrylamide has a molecularweight around 100,000 g/mol and a melting point around 250° C. The firstset was mixed in a 300 mL water solution and placed in the HPHT cellabove the rock sample covered by the drilling fluid residue. The cellwas then heated to 100° C. at 500 psi pressure (nitrogen gas was used toapply the pressure). EDTA chelating agent at pH 14 was added to thethermochemical agent to a final EDTA concentration of 25 wt. %. Themixture was reacted, and the pressure and temperature inside the cellwere monitored over time.

The second set of thermochemical agent included ammonium chloride,NH₄Cl, and sodium nitrite, NaNO₂, salts. The salts were prepared in oneto one (1:1) molar ratio and mixed with EDTA chelating agent at pH of14. The final concentration of EDTA chelating agent was 25 wt. % in theapprox. 1M solution. Similar to the previous set, the reaction wastriggered by heating the HPHT cell to 100° C. (the reaction can betriggered by a temperature as low as 50° C. but this will take longertime, i.e., at least one hour). Pressure and temperature profiles insidethe cell were monitored over time. In this experiment, different molarconcentrations of thermochemicals were used, e.g., 1 mol/L, 2 mol/L, 3mol/L.

In-situ heat and pressure pulse can be generated by different methods.For example, heat and pressure can be generated by magnesium sulfateheptahydrate, MgSO₄.7H₂O, and/or a combined solution of ammoniumchloride (or other ammonium salts) and sodium nitrite (or other nitrite)salts. The magnesium sulfate has complications related to handling andstoring in addition to the possibility of scale formation downhole. Theammonium-with-nitrite method is comparatively safe and easy to handle.

The ammonium-with-nitrite method can be used for different types offilter cakes and drilling fluid residues, insofar as the proper type ofdissolver/solubilizer is selected in addition to the thermochemicalagent(s). For example, in the case of calcium carbonate drilling fluidresidue, chelating agents including Na₄EDTA, Na₄GLDA, and/or Na₃HEDTA,may be preferred to dissolve the calcium carbonate.

In the case that the downhole temperature is insufficient to trigger thereaction (or dehydration in the case of MgSO₄.7H₂O), a second mechanismmay be used in which an external buffer is used to trigger the reaction.Such external buffer may be a low pH chelating agent, such as HEDTA orGLDA. In the case of MgSO₄.7H₂O, the initiation of the thermochemicalactivity requires a temperature of at least 100° C., then magnesiumsulfate will dehydrate, releasing hot water or steam.

Referring now to the drawings, wherein like reference numerals designateidentical or corresponding parts throughout the several views.

FIG. 1 shows the coreflooding set-up used in the Examples. Thearrangement includes at least one inlet for compressed air, fed into awalled space, optionally through a valve including a pressure gageand/or further measurement interfaces. The compressed air is fed into awalled space or chamber, which may have a heating jacket integrated intoits wall and/or penetrating into the space. The walled space may containthe removal formation upon a filter cake layer upon a filter medium orfilter media, resting upon a base.

Effect of Initial Temperature on the Reaction Time

The chemical reaction of the exemplary thermochemical agents used in theExamples can be described by Equation 1 as follows:

NH₄Cl+NaNO₂→NaCl+2H₂O+N₂+ΔH   Eq. 1,

wherein ΔH is the generated heat. The reaction in Eq. 1 requires heat tostart, and the reaction time is a function of the initial temperature.The reaction (e.g., ratio of NH₄Cl to NaNO₂) in Eq. 1, at one to one(1:1) molar ratio, generated an additional temperature of 90° C. and attwo to two (2:2) molar ratio, i.e., twice the concentration, relative toEDTA, generated and additional temperature of 115° C. Different initialtemperatures were used from 50 to 100° C., with these temperaturesrepresenting the downhole reservoir temperatures.

FIG. 2 shows the effect of reservoir temperature on the reaction time.As shown in FIG. 2, the duration of the reaction reaching the maximumtemperature is a function of the initial reservoir or wellboretemperature at the time of reaction. The maximum generated temperaturegenerally adds to the initial wellbore temperature. For example, in thecase of a 1:1 molar ratio of thermochemical agents the relative to EDTAconcentration may be 20-25 wt. %, the cell temperature reached 190° C.when the starting temperature was 100° C. The generated pressure in allcases reached 1500 psi and started to decline to 500 psi during theexperiment, attributable to drilling fluid residue removal. The durationof the experiment was changed from 6 to 24 hours, and the drilling fluidresidue removal efficiency was determined as a function of removal time.The removal efficiency was calculated by taking the disc weight beforeand after the removal process, and this difference was divided by theoriginal disk weight (including the drilling fluid residue).

Possible Mechanisms of Drilling Fluid Residue Removal by Thermochemicalsand EDTA

The experiments on the drilling fluid residue removal (filter cake) inboth oil and water-based drilling fluids were conducted at an initialtemperature of 100° C. and an initial pressure of 500 psi for differentsoaking times. Two different thermochemical molar concentrationsrelative to EDTA were tested, i.e., 1:1 and 2:2 molar ratios. The firstset of experiments were conducted using the water-based drilling fluid.

FIG. 3A, 3B, 4A, and 4B show photos for oil-based barite filter cakes(FIG. 3A and 3B) and water-based barite filter cakes (FIGS. 4 A and 4B)that were formed and removed using the HPHT flooding equipment. FIG. 3Ato 4B show the results of using the exemplary 2:2 molar ratiothermochemical formulation combined with 25 wt % EDTA chelating agent.The removal efficiency reached 83% in the oil-based filter cake (FIG.3B). The removal efficiency reached 89% in the water based filter cake(FIG. 4B).

The 2:2 molar ratio thermochemical reaction resulted in a finaltemperature of 210° C. after 10 minutes of reaction, and this thermalload needed 6 hours to dissipate to the cell temperature of 100° C. Thereaction resulted in a final pressure of 1500 psi, which declined to 500psi after 6 hours. The experimental time was 6 hours.

The resulting temperature from the 2:2 molar ratio thermochemicalreaction caused some hydrolysis of the polymer covering the filter cake.In addition, the pressure disturbed the filter cake and removed thepolymer form the surface. This process of polymer removal resulted indirect contact between the EDTA and barite. The resulting pressurepulse, i.e., 1500 psi, disturbed the filter cake as well as the polymerthat covers the filter cake. This disturbance may have increased thesurface area exposed for reaction with both the thermochemical agentsand the EDTA chelating agent. The increase in temperature from 100 to210° C. due to the thermochemical reaction resulted in higher baritesolubility.

FIG. 5 shows the barite solubility as a function of temperature in 25wt. % EDTA in water the final solution after adding thermochemicalreactants at pH of 14. Increases in temperature correspondinglyincreased EDTA diffusion into the filter cake surface, and enhanced thedissolving power. In addition, increasing the temperature increased thereaction rate, allowing the filter cake to be removed in less timecompared to low temperatures.

The increase in the barite solubility, i.e., dissolution rate, withincreasing temperature may be explained by the reaction kinetics of the25 wt. % K₄EDTA solution with barite. Experiments on this reaction wereconducted for barite discs using rotating disk apparatus, and moredetail about the reaction kinetics of barite with chelating agents isdescribed in Energy and Fuels 2018, 32, 9813-9821, and SPE Drilling &Completion 2019, 34(1), SPE-187122-PA (16-26), each of which isincorporated by reference herein in its entirety. The relationshipbetween the dissolution rate of barite and the EDTA diffusioncoefficient are shown below in Equation 2:

$\begin{matrix}{{R_{d} = {\frac{0.60248\left( \frac{\mu_{f}}{\rho_{f}D_{e}} \right)^{- \frac{2}{3}}C_{b}\sqrt{\frac{\mu}{\rho}}}{1 + {0.2980\left( \frac{\mu_{f}}{\rho_{f}D_{e}} \right)^{- \frac{1}{3}}} + {{0.1}451\left( \frac{\mu_{f}}{\rho_{f}D_{e}} \right)^{- \frac{2}{3}}}}\omega^{\frac{1}{2}}}},} & {{Eq}.\mspace{11mu} 2}\end{matrix}$

wherein Rd is the reaction rate in mole/cm²·s, μ_(f) is the viscosity ofthe 25 wt. % K₄EDTA in g/(s·cm), ρ is the density of K₄EDTA in g/cm³,D_(e) is the diffusion coefficient in cm²/s, C_(b) is the molarconcentration of K₄EDTA (0.75 M in this case), and ω is the diskrotational speed in Hz or s⁻¹. The effect of the generated temperatureusing thermochemical agents on the 25 wt. % K₄EDTA diffusion coefficientwas investigated at three different temperatures, i.e., 100, 125, and150° C.

FIG. 6 shows the diffusion coefficient at the temperatures 100, 125, and150° C. The diffusion coefficient increased significantly withtemperature which, in turn, was observed to increase the dissolutionrate of barite filter cake.

The effect of a pressure pulse on the disturbance of the filter cake wasstudied by testing the filter cake solubility at 210° C. with andwithout thermochemical fluids at 1500 psi. All other parameters wereheld constant as if the thermochemical reaction were to proceed exceptfor the pressure pulse. A second experiment was performed for comparisonto the above experiment. The thermochemical-free experiment wasconducted after the formation of the water-based barite filter cakeusing the HPHT cell. EDTA chelating agent at 25 wt. % concentration inwater and pH of 14 was used at a temperature of 210° C. and a pressureof 1500 psi. This experiment was compared to the initial experiment thatwas conducted using the combined thermochemical-EDTA chelating agentsolution. The filter cake removal efficiency for the second,thermochemical-free experiment was 75%, compared to 89% for the firstcase (using the thermochemical agents). These results support theconclusion that the pressure pulse generated by the thermochemicalreaction disturbed the filter cake integrity and exposed more surfacearea for the reaction.

FIG. 7 shows the effect of barite surface area on the reaction with 25wt. % EDTA chelating agent at 100° C. The average particle size of theindustrial barite that is typically used in drilling fluid preparationis 40 microns. Barite particle size has an effect on the baritesolubility in 25 wt % EDTA chelating agent. The set of solubilityexperiments plotted in FIG. 7 were conducted at 210° C. for 6 hoursusing 25 wt. % EDTA at pH 14. Lower barite particle size yielded thehighest solubility as shown in FIG. 7. A maximum barite solubility wasobtained for a 40-micron size and the lowest solubility was for thelargest particle size of 200-micron. Smaller particle sizes resulted inlarger surface areas as is described by

Equation 3, below:

$\begin{matrix}{{{SSA} = {\sum\limits_{t = 1}^{n}{\frac{6}{d_{i}\rho}\left( \frac{w_{i}F}{100} \right)}}},} & {{Eq}.\mspace{14mu} 3}\end{matrix}$

wherein SSA is the specific surface area in m²/kg, w_(i) is the weightpercentage in size fraction i, F is the surface shape factor (between1.1 and 1.15), d_(i) is the geometric mean size of particle sizefraction i in cm, ρ is the apparent density of the particle in kg/m³,and n is the number of size fractions.

The reaction rate of EDTA chelating with barite is affected by thesurface area exposed to the reaction, which is likewise influenced bythe particle surface area, which can be described by Equation 4, below:

R _(m) =r _(m) S _(m)   Eq. 4,

wherein R_(m) is the reaction rate of the mineral, r_(m) is the specificreaction rate constant for the mineral, and S_(m) is the mineral surfacearea. Equation 4 indicates that the reaction and solubility of baritemineral is a function of the surface area exposed for reaction.

FIG. 8 shows the effect of exposure time on the filter cake removal. Theremoval efficiency in the experiments did not show significant changeafter 6 hours of reaction. This may be attributed to the fact that,after 6 hours, the 25 wt. % EDTA solution may have become saturated withbarite thereby retarding further reaction with and/or solubilization ofthe existing barite in solution. As shown in FIG. 8, a substantiallycomplete dissolution for the filter cake removal of barite weightedwater-based drilling fluids using a combined thermochemical/EDTAtreatment can be achieved by 6 hours.

The diffusion coefficient of EDTA chelating agent is a function of thebarium concentration in solution. After 6 hours, the bariumconcentration reached 15,000 ppm. This high concentration, i.e., 15,000ppm or 1.5%, retarded the reaction of EDTA and resulted in minor changesin the barite solubility at higher soaking times. The EDTA diffusion tothe barite surface was indicated to be inversely proportional to thebarite concentration in solution.

Numerous modifications and variations of the present invention arepossible in light of the above teachings. It is therefore to beunderstood that within the scope of the appended claims, the inventionmay be practiced otherwise than as specifically described herein.

1. A wellbore wall clean up method, the method comprising: injecting adrilling fluid comprising water, bentonite, a salt, barite and CaCO₃into a wellbore in a subterranean formation: introducing an aqueouscomposition into the wellbore and contacting the aqueous compositionwith a wellbore face coated with a filter cake mass; and exothermicallyreacting at least two components present in the aqueous composition inthe wellbore sufficient to raise a temperature, cause a pressure surge,or both raise a temperature and cause a pressure surge at the wellboreface to disrupt the filter cake mass from the wellbore face, wherein theaqueous composition comprises, at a pH of no less than 10: a hydratedsulfate salt and a polyacrylamide, wherein the hydrated sulfate salt isan alkaline metal sulfate salt or an alkaline earth metal sulfate withsaturated hydration; and at least 20 wt. % ethylenediamine tetraaceticacid, based on total aqueous composition weight. 2-8. (canceled)
 9. Themethod of claim 1, wherein the hydrated sulfate salt comprises at least95 wt. % Na₂SO₄.10H₂O, relative to total sulfate salt weight.
 10. Themethod of claim 1, wherein the hydrated sulfate salt comprises at least95 wt. % MgSO₄.7H₂O, relative to total sulfate salt weight. 11.(canceled)
 12. The method of claim 1, wherein the aqueous compositioncomprises the ethylenediamine tetraacetic acid in a range of from 22.5to 30 wt. % of the total aqueous composition weight.
 13. (canceled) 14.The method of claim 1, wherein the drilling fluid comprises at least 65wt. % of barite.
 15. The method of claim 1, which achieves the removalof at least 85 wt. % of the filter cake mass within 6 hours.
 16. Themethod of claim 1, wherein at least 95% of the removal of the filtercake mass achievable by the method is within 6 hours after theintroducing starts. 17-20. (canceled)